Copano Energy Reports Third Quarter 2011 Results

Operating Segment Gross Margin Increased 32% and Service Throughput Increased 23% Over 2010

Nov 03, 2011, 16:39 ET from Copano Energy, L.L.C.

HOUSTON, Nov. 3, 2011 /PRNewswire/ -- Copano Energy, L.L.C. (NASDAQ:  CPNO) today announced its financial results for the three and nine months ended September 30, 2011.

"We are pleased with our third quarter results as our operating segment gross margin continues to benefit from growing volumes in the Eagle Ford Shale and the north Barnett Shale Combo areas and a strong NGL pricing environment," said R. Bruce Northcutt, Copano Energy's President and Chief Executive Officer.

"We are making significant progress on our Eagle Ford Shale strategy as we complete and integrate the bulk of our 2011 projects, several of which have begun accepting volumes on a limited basis.

"We continue to see strong producer activity in the Eagle Ford Shale and when these projects are placed into full-service, they will have an immediate and positive impact on our distributable cash flow and distribution coverage," Northcutt added.

Third Quarter Financial Results

Total distributable cash flow for the third quarter of 2011 increased 3% to $36.9 million from $35.7 million for the third quarter of 2010 and decreased 2% from $37.6 million in the second quarter of 2011.  Third quarter 2011 total distributable cash flow represents 95% coverage of the third quarter distribution of $0.575 per unit, based on common units outstanding on the distribution record date.

Revenue for the third quarter of 2011 increased 49% to $353.7 million compared to $237.7 million for the third quarter of 2010 and increased 2% compared to $346.1 million in the second quarter of 2011.  Operating segment gross margin increased 32% to $72.8 million compared to $55.3 million for the third quarter of 2010 and decreased 4% compared to $75.6 million in the second quarter of 2011.  Total segment gross margin increased 12% to $64.8 million for the third quarter of 2011 compared to $57.9 million for the third quarter of 2010 and decreased 1% compared to $65.3 million for the second quarter of 2011.

Adjusted EBITDA for the third quarter of 2011 was $51.8 million compared to $51.0 million for the third quarter of 2010 and $54.4 million for the second quarter of 2011.

Net loss was $157.7 million for the third quarter of 2011 compared to net income of $7.3 million for the third quarter of 2010.  Net loss for the third quarter of 2011 includes a $170 million non-cash impairment charge relating to the Company's assets in the Rocky Mountains primarily based on a downward shift in the Colorado Interstate Gas forward price curve and our expectations of a continued weak outlook for Rocky Mountains natural gas prices and drilling activity in Wyoming's Powder River Basin.

Net loss to common units after deducting $8.3 million of in-kind preferred unit distributions totaled $166.0 million, or $2.51 per unit on a diluted basis, for the third quarter of 2011 compared to net loss to common units of $0.2 million, or less than $0.01 per unit on a diluted basis, for the third quarter of 2010.  Weighted average diluted units outstanding totaled 66.2 million for the third quarter of 2011 as compared to 65.7 million for the same period in 2010.  Excluding the impact of the non-cash impairment charge, adjusted net income to common units totaled $4.0 million, or approximately $0.06 per unit on a diluted basis, for the third quarter of 2011.

Total distributable cash flow, total segment gross margin, adjusted EBITDA, segment gross margin and adjusted net income are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures at the end of this press release.  Commencing with the second quarter of 2011, Copano revised its method for calculating adjusted EBITDA and its presentation of total distributable cash flow.  For a detailed discussion of these changes, please read "Use of Non-GAAP Financial Measures" beginning on page 7 of this news release.

Third Quarter Operating Results by Segment

Copano manages its business in three geographical operating segments:  Texas, which provides midstream natural gas services in north and south Texas and also includes a processing plant in southwest Louisiana; Oklahoma, which provides midstream natural gas services in central and east Oklahoma; and the Rocky Mountains, which provides midstream natural gas services to producers in Wyoming's Powder River Basin and includes managing member interests in Bighorn Gas Gathering, L.L.C. (Bighorn) of 51% and in Fort Union Gas Gathering, L.L.C. (Fort Union) of 37.04%.

Texas

Segment gross margin for Texas increased 43% to $44.5 million for the third quarter of 2011 compared to $31.2 million for the third quarter of 2010 and decreased 3% from $46.1 million for the second quarter of 2011.  The year-over-year increase resulted primarily from (i) a 9% increase in realized margins on service throughput compared to the third quarter of 2010 ($0.63 per MMBtu in 2011 compared to $0.58 per MMBtu in 2010) reflecting higher NGL prices and (ii) an increase in pipeline throughput associated with fee-based contracts in the Eagle Ford Shale and the north Barnett Shale Combo plays.  During the third quarter of 2011, throughput volumes for the Eagle Ford Shale and the north Barnett Shale Combo plays increased 25% and 41%, respectively, from the second quarter of 2011.  During the third quarter of 2011, weighted-average NGL prices on the Mont Belvieu index, based on Copano's product mix for the period, were $59.43 per barrel compared to $40.16 per barrel during the third quarter of 2010, an increase of 48%.  During the third quarter of 2011, natural gas prices on the Houston Ship Channel index averaged $4.23 per MMBtu compared to $4.33 per MMBtu during the third quarter of 2010, a decrease of 2%.

During the third quarter of 2011, the Texas segment provided gathering, transportation and processing services for an average of 765,744 MMBtu/d of natural gas compared to 590,116 MMBtu/d for the third quarter of 2010, an increase of 30%.  The Texas segment gathered an average of 463,321 MMBtu/d of natural gas during the third quarter of 2011, an increase of 45% over last year's third quarter, primarily due to increased volumes from the Eagle Ford Shale and north Barnett Shale Combo plays.  Processed volumes increased 33% to an average of 686,398 MMBtu/d of natural gas at Copano's plants and third-party plants.  NGL production increased 57% to an average of 30,904 Bbls/d at Copano's plants and third-party plants, reflecting increased volumes behind Copano's Houston Central complex in south Texas and the Saint Jo plant in the north Barnett Shale Combo play in north Texas.

The decrease in segment gross margin from the second quarter of 2011 was a result of the curtailment of volumes at the Houston Central complex because a scheduled turnaround at the Point Comfort facility caused a downstream market constraint, the scheduled maintenance on the Company's purity propane line, and a decrease in volumes under a short-term and interruptible contract on the DK pipeline offset by increased Eagle Ford Shale volumes.

Oklahoma

Segment gross margin for Oklahoma increased 21% to $27.9 million for the third quarter of 2011 compared to $23.0 million for the third quarter of 2010 and decreased 3% from $28.7 million for the second quarter of 2011.  The year-over-year increase resulted primarily from (i) a 13% increase in realized margins on service throughput compared to the third quarter of 2010 ($1.05 per MMBtu in 2011 compared to $0.93 per MMBtu in 2010), primarily reflecting higher NGL prices, (ii) the acquisition of the Harrah plant on April 1, 2011 and (iii) an increase in service throughput attributable to volume growth from the Woodford Shale.  During the third quarter of 2011, weighted-average NGL prices on the Conway index, based on Copano's product mix for the period, were $49.21 per barrel compared to $36.53 per barrel during the third quarter of 2010, an increase of 35%.  During the third quarter of 2011, natural gas prices on the CenterPoint East index averaged $4.05 per MMBtu compared to $4.14 per MMBtu during the third quarter of 2010, a decrease of 2%.

The Oklahoma segment gathered an average of 288,440 MMBtu/d of natural gas, processed an average of 158,070 MMBtu/d of natural gas and produced an average of 17,453 Bbls/d of NGLs at its own plants and third-party plants during the third quarter of 2011.  Compared to the third quarter of 2010, this represents a 7% increase in service throughput, a 1% increase in plant inlet volumes and a 6% increase in NGL production.  The increase in service throughput is primarily attributable to increased drilling and production of lean gas in the Woodford Shale area near Copano's Cyclone Mountain system, offset by normal production declines in rich gas areas.

The decrease in segment gross margin from the second quarter of 2011 was primarily related to a drop in natural gas and NGL prices.

Rocky Mountains

Segment gross margin for the Rocky Mountains segment totaled $0.4 million in the third quarter of 2011 compared to $1.1 million for the third quarter of 2010 and $0.8 million for the second quarter of 2011.  The Rocky Mountains segment gross margin results do not include the financial results and volumes associated with Copano's interests in Bighorn and Fort Union, which are accounted for under the equity method of accounting and are shown in Copano's financial statements under "Equity in (earnings) loss from unconsolidated affiliates."  Average pipeline throughput for Bighorn and Fort Union on a combined basis decreased 27% to 670,543 MMBtu/d in the third quarter of 2011 as compared to 913,730 MMBtu/d in the third quarter of 2010.  The volume decline is primarily due to certain Fort Union shippers diverting gas volumes to TransCanada's Bison Pipeline upon its start up in January 2011.  Fort Union volumes do not reflect 223,557 MMBtu/d in long-term contractually committed volumes that Fort Union did not gather but which were the basis of payments received by Fort Union for the three months ended September 30, 2011.

Corporate and Other

Corporate and other segment gross margin includes Copano's commodity risk management activities.  These activities contributed a loss of $8.0 million for the third quarter of 2011 compared to income of $2.6 million for the third quarter of 2010 and a loss of $10.3 million for the second quarter of 2011.  The loss for the third quarter of 2011 included $7.4 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio and $2.9 million of net cash settlements paid for expired commodity derivative instruments offset by $2.3 million of unrealized gains on undesignated economic hedges.  The third quarter 2010 gain included $11.1 million of net cash settlements received for expired commodity derivative instruments offset by $8.2 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio and $0.3 million of unrealized mark-to-market losses on undesignated economic hedges.

Year to Date Financial Results

Revenue for the nine months ended September 30, 2011 increased 35% to $989.7 million compared to $734.4 million for the same period in 2010.  Operating segment gross margin increased 34% to $217.6 million compared to $162.6 million for the nine months ended September 30, 2010.  Total segment gross margin increased 15% to $190.5 million for the nine months ended September 30, 2011 compared to $165.9 million for the same period in 2010.

Adjusted EBITDA for the nine months ended September 30, 2011 was $153.6 million compared to $146.3 million for the same period in 2010.

Net loss was $163.6 million for the nine months ended September 30, 2011 compared to net loss of $15.1 million for the same period in 2010.  Net loss for the first nine months of 2011 includes a loss on the refinancing of unsecured debt of $18.2 million and a $170.0 million non-cash impairment charge relating to our Rocky Mountains assets discussed above.  Net loss for the first nine months of 2010 includes a $25 million non-cash impairment charge relating to the Company's investment in Bighorn.

Net loss to common units after deducting $24.2 million of in-kind preferred unit distributions beginning in July 2010 totaled $187.8 million, or $2.84 per unit on a diluted basis, for the nine months ended September 30, 2011 compared to net loss to common units of $22.6 million, or $0.36 per unit on a diluted basis, for the same period in 2010.  Weighted average diluted units outstanding totaled 66.1 million for the nine months ended September 30, 2011 as compared to 63.2 million for the same period in 2010.

Cash Distributions

On October 12, 2011, Copano announced its third quarter 2011 cash distribution of $0.575 per unit, or $2.30 per unit on an annualized basis, for all of its outstanding common units.  This distribution is unchanged from the second quarter of 2011 and will be paid on November 10, 2011 to common unitholders of record at the close of business on October 31, 2011.

Conference Call Information

Copano will hold a conference call to discuss its third quarter 2011 financial results on November 4, 2011 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time).  To participate in the call, dial (480) 629-9818 and ask for the Copano call 10 minutes prior to the start time, or access it live over the internet at www.copanoenergy.com on the "Investor Overview" page of the "Investor Relations" section of Copano's website.

A replay of the audio webcast will be available shortly after the call on Copano's website.  A telephonic replay will be available through November 11, 2011 by calling (303) 590-3030 and using the pass code 4476344#.

Use of Non-GAAP Financial Measures

This news release and the accompanying schedules include the non-generally accepted accounting principles, or non-GAAP, financial measures of total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin.  The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP.  Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), income (loss) from continuing operations, cash flows from operating activities or any other GAAP measure of liquidity or financial performance.  Copano's non-GAAP financial measures may not be comparable to similarly titled measures of other companies, which may not calculate their measures in the same manner.

Copano's management team uses non-GAAP financial measures to evaluate its core profitability and to assess the financial performance of its assets.  Subject to the limitations expressed above, Copano believes that investors and other market participants benefit from access to the same financial measures that its management uses in evaluating its performance.

Adjusted EBITDA.  Commencing with the second quarter of 2011, Copano revised its calculation of adjusted EBITDA to more closely resemble that of many of Copano's peers in terms of measuring the company's ability to generate cash.  Adjusted EBITDA (as revised) equals:

  • net income (loss);
  • plus interest and other financing costs, provision for income taxes, depreciation, amortization and impairment expense, non-cash amortization expense associated with commodity derivative instruments, distributions from unconsolidated affiliates, loss on refinancing of unsecured debt and equity-based compensation expense;
  • minus equity in earnings (loss) from unconsolidated affiliates and unrealized gains (losses) from commodity risk management activities; and
  • plus or minus other miscellaneous non-cash amounts affecting net income (loss) for the period.

In calculating adjusted EBITDA as revised, Copano no longer adds to EBITDA (earnings before interest, taxes, depreciation and amortization) its share of the depreciation, amortization and impairment expense and interest and other financing costs embedded in equity in earnings (loss) from unconsolidated affiliates; instead, Copano now adds to EBITDA (i) other non-cash amounts affecting net income (loss) for the period, (ii) non-cash amortization expense associated with commodity derivative instruments, (iii) loss on refinancing of unsecured debt and (iv) distributions from unconsolidated affiliates.

Copano believes that the revised calculation of adjusted EBITDA is a more effective tool for its management in evaluating operating performance for several reasons.  Although Copano's historical method for calculating adjusted EBITDA was useful in assessing the performance of Copano's assets (including its unconsolidated affiliates) without regard to financing methods, capital structure or historical cost basis, the prior calculation was not as useful in evaluating the core performance of its assets and their ability to generate cash because adjustments for a number of non-cash expenses and other non-cash and non-operating items were not reflected in the calculation, and the impact of cash distributions from unconsolidated affiliates was likewise not reflected.  Additionally, Copano believes that the revised calculation of adjusted EBITDA is more consistent with the method and presentation used by many of its peers and will allow management to better evaluate the company's performance relative to its peer companies.

Also, Copano believes that the revised calculation more effectively represents what lenders and debt holders, as well as industry analysts and many of its unitholders, have indicated is useful in assessing Copano's core performance and outlook and comparing Copano to other companies in its industry.  For example, Copano believes that adjusted EBITDA as revised may provide investors and analysts with a more useful tool for evaluating the company's leverage because it more closely resembles Consolidated EBITDA (as defined under Copano's revolving credit facility), which is used by lenders to calculate financial covenants.  Consolidated EBITDA differs from adjusted EBITDA in that it includes further adjustments to (i) reflect the pro forma effects of material acquisitions and dispositions and (ii) in the case of leverage ratio calculations, includes projected EBITDA from significant capital projects under construction.

Total Distributable Cash Flow.  Commencing with the second quarter of 2011, Copano presents total distributable cash flow as net income (loss) plus all adjustments included in the adjusted EBITDA calculation described above and minus: (i) interest expense, (ii) current tax expense and (iii) maintenance capital expenditures.  Although Copano has revised its presentation of total distributable cash flow, the components of the calculation have not changed, except that total distributable cash flow now eliminates the impact of any loss on refinancing of unsecured debt because such losses do not reduce operating cash flow.

Houston-based Copano Energy, L.L.C. is a midstream natural gas company with operations in Texas, Oklahoma, Wyoming and Louisiana.  Its assets include approximately 6,400 miles of active natural gas gathering and transmission pipelines, 340 miles of NGL pipelines and ten natural gas processing plants, with more than one billion cubic feet per day of combined processing capacity and 22,000 barrels per day of fractionation capacity.  For more information, please visit www.copanoenergy.com.

This press release includes "forward-looking statements," as defined by the Securities and Exchange Commission.  Statements that address activities or events that Copano believes will or may occur in the future are forward-looking statements.  These statements include, but are not limited to, statements about future producer activity and Copano's total distributable cash flow and distribution coverage.  These statements are based on management's experience and perception of historical trends, current conditions, expected future developments and other factors management believes are reasonable.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, without limitation, the following risks and uncertainties, many of which are beyond Copano's control:  The volatility of prices and market demand for natural gas and NGLs; Copano's ability to continue to obtain new sources of natural gas supply and retain its key customers; the impact on volumes and resulting cash flow of technological, economic and other uncertainties inherent in estimating future production and producers' ability to drill and successfully complete and attach new natural gas supplies and the availability of downstream transportation systems and other facilities for natural gas and NGLs; higher construction costs or project delays due to inflation, limited availability of required resources, or the effects of environmental, legal or other uncertainties; general economic conditions; the effects of government regulations and policies; and other financial, operational and legal risks and uncertainties detailed from time to time in Copano's filings with the Securities and Exchange Commission.

– financial statements to follow –


Contacts:

Carl Luna, SVP & CFO


Copano Energy, L.L.C.


713-621-9547




Jack Lascar / jlascar@drg-l.com


Anne Pearson / apearson@drg-l.com


DRG&L / 713-529-6600





COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS






Three Months Ended

September 30,



Nine Months Ended

September 30,











2011


2010



2011


2010





















(In thousands, except per unit information)

Revenue:















Natural gas sales                           


$

120,815


$

87,524



$

348,538


$

292,559


Natural gas liquids sales                     



191,370



118,999




521,129



353,119


Transportation, compression and processing fees   



30,337



17,909




82,706



47,539


Condensate and other                         



11,169



13,272




37,299



41,204



Total revenue                             



353,691



237,704




989,672



734,421

















Costs and expenses:















Cost of natural gas and natural gas liquids(1)     



281,858



174,461




779,986



551,939


Transportation (1)                           



6,991



5,340




19,202



16,619


Operations and maintenance                    



16,091



13,004




46,953



38,337


Depreciation, amortization and impairment        



21,911



15,218




56,143



46,002


General and administrative                     



10,031



9,869




34,530



31,311


Taxes other than income                       



1,502



1,315




4,029



3,658


Equity in loss (earnings) from unconsolidated affiliates  



161,589



(2,049)




158,581



19,788



Total costs and expenses                   



499,973



217,158




1,099,424



707,654

















Operating (loss) income                           



(146,282)



20,546




(109,752)



26,767

Other income (expense):















Interest and other income                       



16



15




31



59


Loss on refinancing of unsecured debt           








(18,233)




Interest and other financing costs                



(11,080)



(12,943)




(34,450)



(41,239)

(Loss) income before income taxes                 



(157,346)



7,618




(162,404)



(14,413)

Provision for income taxes                          



(390)



(320)




(1,161)



(660)

Net (loss) income                                



(157,736)



7,298




(163,565)



(15,073)

Preferred unit distributions                         



(8,279)



(7,500)




(24,235)



(7,500)

Net loss to common units                          


$

(166,015)


$

(202)



$

(187,800)


$

(22,573)

















Basic and diluted net loss per common unit            


$

(2.51)


$



$

(2.84)


$

(0.36)

Weighted average number of common units             



66,246



65,658




66,125



63,193

































Distributions declared per common unit               


$

0.575


$

0.575



$

1.725


$

1.725

















(1) Exclusive of operations and maintenance and depreciation, amortization and impairment shown separately below.













COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS








Nine Months Ended September 30,







2011



2010

Cash Flows From Operating Activities:



(In thousands)


Net loss                                                              


$

(163,565)



$

(15,073)


Adjustments to reconcile net loss to net cash provided by operating activities:










Depreciation, amortization and impairment                                 



56,143




46,002



Amortization of debt issue costs                                       



2,855




2,773



Equity in loss from unconsolidated affiliates                               



158,581




19,788



Distributions from unconsolidated affiliates                               



17,961




16,999



Loss on refinancing of unsecured debt                                   



18,233






Non-cash gain on risk management activities, net                            



(4,723)




(555)



Equity-based compensation                                           



7,445




7,118



Deferred tax provision                                               



253




(19)



Other non-cash items                                                 



(86)




(458)



Changes in assets and liabilities, net of acquisitions:











Accounts receivable                                               



(11,132)




10,586




Prepayments and other current assets                                 



(2,952)




2,135




Risk management activities                                          



11,353




10,766




Accounts payable                                                 



17,459




(6,518)




Other current liabilities                                             



14,964




945





Net cash provided by operating activities                             



122,789




94,489













Cash Flows From Investing Activities:









Additions to property, plant and equipment                                  



(175,323)




(101,265)


Additions to intangible assets                                             



(5,316)




(2,259)


Acquisitions                                                           



(16,084)





Investments in unconsolidated affiliates                                     



(105,111)




(11,186)


Distributions from unconsolidated affiliates                                  



2,368




2,555


Escrow cash                                                         



6





Proceeds from sale of assets                                             



248




279


Other                                                               



98




280





Net cash used in investing activities                                  



(299,114)




(111,596)













Cash Flows From Financing Activities:









Proceeds from long-term debt                                            



725,000




80,000


Repayment of long-term debt                                             



(412,665)




(350,000)


Payments of premiums and expenses on redemption of unsecured debt           



(14,572)




-


Deferred financing costs                                                 



(15,743)




(995)


Distributions to unitholders                                               



(114,834)




(107,612)


Proceeds from issuance of Series A convertible preferred units, net of underwriting










discounts and commissions of $8,935                                    






291,065


Proceeds from public offering of common units, net of underwriting discounts










and commissions of $7,223                                            






164,786


Equity offering costs                                                   



(4)




(6,236)


Proceeds from option exercises                                            



2,747




3,188





Net cash provided by financing activities                             



169,929




74,196













Net (decrease) increase in cash and cash equivalents                           



(6,396)




57,089

Cash and cash equivalents, beginning of year                                 



59,930




44,692

Cash and cash equivalents, end of period                                     


$

53,534



$

101,781






COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS












September 30,


December 31,




2011


2010















(In thousands, except unit information)

ASSETS

Current assets:








Cash and cash equivalents                                                 


$

53,534


$

59,930


Accounts receivable, net                                                   



108,339



96,662


Risk management assets                                                   



12,101



7,836


Prepayments and other current assets                                        



8,311



5,179



Total current assets                                                     



182,285



169,607










Property, plant and equipment, net                                               



1,078,948



912,157

Intangible assets, net



179,992



188,585

Investments in unconsolidated affiliates                                          



529,958



604,304

Escrow cash



1,850



1,856

Risk management assets                                                     



17,128



11,943

Other assets, net



27,739



18,541



Total assets


$

2,017,900


$

1,906,993










LIABILITIES AND MEMBERS' CAPITAL

Current liabilities:








Accounts payable


$

140,792


$

117,706


Accrued interest



19,945



10,621


Accrued tax liability                                                       



892



913


Risk management liabilities                                                  



7,285



9,357


Other current liabilities                                                     



33,948



14,495



Total current liabilities                                                   



202,862



153,092










Long term debt (includes $0 and $546 bond premium as of September 30, 2011








and December 31, 2010, respectively)                                         



904,525



592,736

Deferred tax liability



2,135



1,883

Risk management and other noncurrent liabilities                                   



2,150



4,525










Commitments and contingencies (Note 9)







Members' capital:








Series A convertible preferred units, no par value, 11,399,097 units and









10,585,197 units issued and outstanding as of September 30, 2011 and









December 31, 2010, respectively                                          



285,168



285,172


Common units, no par value, 66,270,176 units and 65,915,173 units issued and









outstanding as of September 30, 2011 and December 31, 2010, respectively         



1,164,399



1,161,652

Paid in capital



59,250



51,743

Accumulated deficit



(592,676)



(313,454)

Accumulated other comprehensive loss                                          



(9,913)



(30,356)






906,228



1,154,757



Total liabilities and members' capital                                         


$

2,017,900


$

1,906,993





COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED RESULTS OF OPERATIONS







Three Months Ended

September 30,


Nine Months Ended

September 30,






2011


2010


2011


2010























($ In thousands)


Total segment gross margin(1)                           


$

64,842


$

57,903


$

190,484


$

165,863


Operations and maintenance expenses                    



16,091



13,004



46,953



38,337


Depreciation, amortization and impairment                  



21,911



15,218



56,143



46,002


General and administrative expenses                       



10,031



9,869



34,530



31,311


Taxes other than income                                 



1,502



1,315



4,029



3,658


Equity in loss (earnings) from unconsolidated affiliates(2)      



161,589



(2,049)



158,581



19,788



Operating (loss) income                           



(146,282)



20,546



(109,752)



26,767


Loss on refinancing of unsecured debt                     







(18,233)




Interest and other financing costs, net                       



(11,064)



(12,928)



(34,419)



(41,180)


Provision for income taxes                               



(390)



(320)



(1,161)



(660)


Net (loss) income                                     



(157,736)



7,298



(163,565)



(15,073)


Preferred unit distributions                              



(8,279)



(7,500)



(24,235)



(7,500)


Net loss to common units                               


$

(166,015)


$

(202)


$

(187,800)


$

(22,573)


















Total segment gross margin:















Texas                                           


$

44,540


$

31,218


$

135,685


$

90,134



Oklahoma                                       



27,876



23,010



79,623



69,106



Rocky Mountains(3)                               



432



1,091



2,245



3,342




Segment gross margin                          



72,848



55,319



217,553



162,582



Corporate and other(4)                             



(8,006)



2,584



(27,069)



3,281




Total segment gross margin(1)                    


$

64,842


$

57,903


$

190,484


$

165,863


















Segment gross margin per unit:















Texas:
















Service throughput ($/MMBtu)                    


$

0.63


$

0.58


$

0.71


$

0.57



Oklahoma:
















Service throughput ($/MMBtu)                    


$

1.05


$

0.93


$

1.04


$

0.97

















Volumes:















Texas: (5)
















Service throughput (MMBtu/d)(6)                  



765,744



590,116



694,802



577,678




Pipeline throughput (MMBtu/d)                     



463,321



319,538



436,210



321,450




Plant inlet volumes (MMBtu/d)                      



686,398



516,949



612,405



481,285




NGLs produced (Bbls/d)                          



30,904



19,685



27,040



17,818



Oklahoma:(7)
















Service throughput (MMBtu/d)(6)                  



288,440



270,184



286,320



259,710




Plant inlet volumes (MMBtu/d)                      



158,070



156,676



160,737



156,771




NGLs produced (Bbls/d)                          



17,453



16,541



17,498



16,180

















Capital Expenditures:















Maintenance capital expenditures                     


$

3,510


$

3,290


$

11,111


$

6,370



Expansion capital expenditures                       



82,675



29,290



203,576



101,232




Total capital expenditures                         


$

86,185


$

32,580


$

214,687


$

107,602

















Operations and maintenance expenses:















Texas                                           


$

9,082


$

6,779


$

26,815


$

20,845



Oklahoma                                       



6,930



6,163



19,943



17,266



Rocky Mountains                                 



79



62



195



226




Total operations and maintenance expenses         


$

16,091


$

13,004


$

46,953


$

38,337






(1)

Total segment gross margin is a non-GAAP financial measure.  Please read "How We Evaluate Our Operations" for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.

(2)

Includes results and volumes associated with our unconsolidated affiliates.  The following table summarizes the throughput for the periods indicated:








Three Months Ended

September 30,

Nine Months Ended

September 30,



2011

2010

2011

2010

Bighorn and Fort Union(a)   

MMBtu/d

670,543

913,730

595,302

914,967

Southern Dome






Plant inlet

MMBtu/d

11,970

12,338

11,630

13,046

NGLs produced         

Bbls/d

429

444

418

466

Webb Duval(b)

MMBtu/d

48,628

53,668

48,705

56,145

Eagle Ford Gathering

MMBtu/d

58,295

58,295

Liberty Pipeline Group

Bbls/d

4,252

4,252

___________________________






(a) The volume decline is primarily due to certain Fort Union shippers diverting gas volumes to TransCanada's Bison Pipeline upon its start up in January 2011.  Fort Union volumes do not reflect an additional 223,557 MMBtu/d and 279,918 MMBtu/d in long-term contractually committed volumes that Fort Union did not gather but which were the basis of payments received by Fort Union for the three and nine months ended September 30, 2011, respectively.

(b) Net of intercompany volumes.






(3)

Rocky Mountains segment gross margin includes results from producer services, including volumes purchased for resale, volumes gathered under firm capacity gathering agreements with Fort Union, volumes transported using our firm capacity agreements with Wyoming Interstate Gas Company and compressor rental services provided to Bighorn.  Excludes results and volumes associated with our interest in Bighorn and Fort Union.

(4)

Corporate and other includes results attributable to our commodity risk management activities.

(5)

Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Texas segment at all plants, including plants owned by the Texas segment and plants owned by third parties.

(6)

"Service throughput" means the volume of natural gas delivered to our wholly owned processing plants by third-party pipelines plus our "pipeline throughput," which is the volume of natural gas transported or gathered through our pipelines.

(7)

Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including plants owned by the Oklahoma segment and plants owned by third parties.





COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED NON GAAP FINANCIAL MEASURES














Three Months Ended

September 30,


Nine Months Ended

September 30,












2011


2010


2011


2010



















($ In thousands)

Reconciliation of total segment gross margin to operating (loss) income:




Operating (loss) income


$

(146,282)


$

20,546


$

(109,752)


$

26,767


Add:  



16,091



13,004



46,953



38,337


Operations and maintenance expenses



Depreciation, amortization and impairment



21,911



15,218



56,143



46,002



General and administrative expenses



10,031



9,869



34,530



31,311



Taxes other than income



1,502



1,315



4,029



3,658



Equity in loss (earnings) from unconsolidated affiliates



161,589



(2,049)



158,581



19,788

Total segment gross margin


$

64,842


$

57,903


$

190,484


$

165,863

















Reconciliation of EBITDA, adjusted EBITDA and total distributable














cash flow to net (loss) income:














Net (loss) income


$

(157,736)


$

7,298


$

(163,565)


$

(15,073)


Add:  



21,911



15,218



56,143



46,002


Depreciation, amortization and impairment



Interest and other financing costs



11,080



12,943



34,450



41,239



Provision for income taxes



390



320



1,161



660

EBITDA



(124,355)



35,779



(71,811)



72,828


Add:  



7,442



8,163



22,069



24,211


Amortization of commodity derivative options



Distributions from unconsolidated affiliates



6,757



6,563



20,329



19,554



Loss on refinancing of unsecured debt







18,233





Equity-based compensation



2,093



2,448



9,184



7,849



Equity in loss (earnings) from unconsolidated affiliates



161,589



(2,049)



158,581



19,788



Unrealized (gain) loss from commodity risk management activities



(2,332)



389



(2,695)



150



Other non-cash operating items



576



(295)



(272)



1,933

Adjusted EBITDA



51,770



50,998



153,618



146,313


Less:  



(11,029)



(11,856)



(33,623)



(39,171)


Interest expense



Current income tax expense and other



(305)



(141)



(929)



(740)



Maintenance capital expenditures



(3,510)



(3,290)



(11,111)



(6,370)

Total distributable cash flow


$

36,926


$

35,711


$

107,955


$

100,032












Three Months Ended

September 30,







2011 


2010 





(In thousands, except per unit information)


Reconciliation of adjusted net income and adjusted net income per unit:









Net loss to common units


$

(166,015)


$

(202)



Non-cash impairment charge



170,000





Adjusted net income to common units


$

3,985


$

(202)



Diluted net loss per common unit


$

(2.51)


$



Diluted adjusted net income per common unit


$

0.06


$



Weighted average number of diluted common units                                             



66,246



65,658



Restricted units, phantom units, options, unit appreciation rights and contingent units                  



838





Adjusted weighted average number of diluted common units                                     



67,084



65,658





































SOURCE Copano Energy, L.L.C.



RELATED LINKS

http://www.copanoenergy.com